Oilfield drilling fluid, often called “mud,” serves multiple purposes in the industry. Among its many functions, the drilling mud acts as a lubricant to cool rotary drill bits and facilitate faster cutting rates. The mud may be mixed at the surface and pumped downhole at high pressure to the drill bit through a bore of the drillstring. Once the mud reaches the drill bit, it exits through various nozzles and ports where it lubricates and cools the drill bit. After exiting through the nozzles, the “spent” fluid returns to the surface through an annulus formed between the drillstring and the drilled wellbore.
Furthermore, drilling mud provides a column of hydrostatic pressure, or head, to prevent “blow out” of the well being drilled. This hydrostatic pressure offsets formation pressures thereby preventing fluids from blowing out if pressurized deposits in the formation are breeched. Two factors contributing to the hydrostatic pressure of the drilling mud column are the height (or depth) of the column (i.e., the vertical distance from the surface to the bottom of the wellbore) itself and the density (or its inverse, specific gravity) of the fluid used. Depending on the type and construction of the formation to be drilled, various weighting and lubrication agents are mixed into the drilling mud to obtain the right mixture. Drilling mud weight may be reported in “pounds,” short for pounds per gallon. Increasing the amount of weighting agent solute dissolved in the mud base may create a heavier drilling mud. Drilling mud that is too light may not protect the formation from blow outs, and drilling mud that is too heavy may over invade the formation. Therefore, much time and consideration is spent to ensure the mud mixture is optimal. Because the mud evaluation and mixture process is time consuming and expensive, drillers and service companies reclaim the returned drilling mud and recycle it for continued use.
Drilling mud is also used to carry the cuttings away from the drill bit at the bottom of the borehole to the surface. As a drill bit pulverizes or scrapes the rock formation at the bottom of the borehole, small pieces of solid material are left behind. The drilling fluid exiting the nozzles at the bit acts to stir-up and carry the solid particles of rock and formation to the surface within the annulus between the drillstring and the borehole. Therefore, the fluid exiting the borehole from the annulus is a slurry of formation cuttings in drilling mud. Before the mud can be recycled and re-pumped down through nozzles of the drill bit, the cutting particulates need to be removed.
Apparatuses in use today to remove cuttings and other solid particulates from drilling fluid are commonly referred to in the industry as shale shakers or vibratory separators. A vibratory separator is a vibrating sieve-like table or screening deck upon which returning solids laden drilling fluid is deposited, and through which drilling fluid, that has been separated from much of the solids, emerges from the vibratory separator. The vibratory separator may be an angled table with a perforated filter screen bottom. Returning drilling fluid is deposited at a feed end of the vibratory separator. As the drilling fluid travels down length of the vibrating table, the fluid falls through the perforations to a reservoir below leaving the solid particulate material behind.
Filter screens may include a perforated plate base upon which a wire mesh, and/or other perforated filter overlay, is positioned. The perforated plate base generally provides structural support and allows the passage of fluids therethrough. A vibratory separator may have multiple screens which are held in place by two wedges, one on each side of each screen.